SECTION 18 POWER DISTRIBUTION Daniel J.Ward Principal Engineer, Dominion Virginia Power; Fellow, IEEE; Chair, IEEE Distribution Subcommittee; Chair, ANSI C84.1 Committee, Past Vice Chair (PES), Power Quality Standards Coordinating Committee CONTENTS 18.1 DISTRIBUTION DEFINED . . . . . . . . . . . . . . . . . . . . . . .18-2 18.2 DISTRIBUTION-SYSTEM AUTOMATION . . . . . . . . . . .18-7 18.3 CLASSIFICATION AND APPLICATION OF DISTRIBUTION SYSTEMS . . . . . . . . . . . . . . . . . . . .18-8 18.4 CALCULATION OF VOLTAGE REGULATION AND I2R LOSS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-9 18.5 THE SUBTRANSMISSION SYSTEM . . . . . . . . . . . . . .18-16 18.6 PRIMARY DISTRIBUTION SYSTEMS . . . . . . . . . . . . .18-20 18.7 THE COMMON-NEUTRAL SYSTEM . . . . . . . . . . . . . .18-25 18.8 VOLTAGE CONTROL . . . . . . . . . . . . . . . . . . . . . . . . . .18-27 18.9 OVERCURRENT PROTECTION . . . . . . . . . . . . . . . . . .18-31 18.10 OVERVOLTAGE PROTECTION . . . . . . . . . . . . . . . . . . .18-42 18.11 DISTRIBUTION TRANSFORMERS . . . . . . . . . . . . . . .18-48 18.12 SECONDARY RADIAL DISTRIBUTION . . . . . . . . . . .18-50 18.13 BANKING OF DISTRIBUTION TRANSFORMERS . . .18-52 18.14 APPLICATION OF CAPACITORS . . . . . . . . . . . . . . . . .18-53 18.15 POLES AND STRUCTURES . . . . . . . . . . . . . . . . . . . . .18-56 18.16 STRUCTURAL DESIGN OF POLE LINES . . . . . . . . . .18-62 18.17 LINE CONDUCTORS . . . . . . . . . . . . . . . . . . . . . . . . . .18-68 18.18 OPEN-WIRE LINES . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-70 18.19 JOINT-LINE CONSTRUCTION . . . . . . . . . . . . . . . . . . .18-71 18.20 UNDERGROUND RESIDENTIAL DISTRIBUTION . . .18-72 18.21 UNDERGROUND SERVICE TO LARGE COMMERCIAL LOADS . . . . . . . . . . . . . . . . . . . . . . . .18-77 18.22 LOW-VOLTAGE SECONDARY-NETWORK SYSTEMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-80 18.23 CONSTRUCTION OF UNDERGROUND SYSTEMS FOR DOWNTOWN AREAS . . . . . . . . . . . . . . . . . . . . . .18-83 18.24 UNDERGROUND CABLES . . . . . . . . . . . . . . . . . . . . . .18-87 18.25 FEEDERS FOR RURAL SERVICE . . . . . . . . . . . . . . . .18-98 18.26 DEMAND AND DIVERSITY FACTORS . . . . . . . . . . .18-102 18.27 DISTRIBUTION ECONOMICS . . . . . . . . . . . . . . . . . .18-103 18.28 DISTRIBUTION SYSTEM LOSSES . . . . . . . . . . . . . .18-107 18.29 STREET-LIGHTING SYSTEMS . . . . . . . . . . . . . . . . . .18-109 18.30 RELIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-110 18.31 EUROPEAN PRACTICES . . . . . . . . . . . . . . . . . . . . . .18-112 BIBLIOGRAPHY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-115 18-1 Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. Source: STANDARD HANDBOOK FOR ELECTRICAL ENGINEERS18-2 SECTION EIGHTEEN FIGURE 18-1 Typical distribution system. 18.1 DISTRIBUTION DEFINED Broadly speaking, distribution includes all parts of an electric utility system between bulk power sources and the consumers’ service-entrance equipments. Some electric utility distribution engineers, however, use a more limited definition of distribution as that portion of the utility system between the distribution substations and the consumers’ service-entrance equipment. In general, a typical distributtio system consists of (1) subtransmission circuits with voltage ratings usually between 12.47 and 345 kV which deliver energy to the distribution substations, (2) distribution substations which convert the energy to a lower primary system voltage for local distribution and usually include facilities for voltage regulation of the primary voltage, (3) primary circuits or feeders, usually operating in the range of 4.16 to 34.5 kV and supplying the load in a well-defined geographic area, (4) distribution transformers in ratings from 10 to 2500 kVA which may be installed on poles or grade-level pads or in underground vaults near the consumers and transform the primary voltages to utilization voltages, (5) secondary circuits at utilization voltage which carry the energy from the distribution transformer along the street or rear-lot lines, and (6) service drops which deliver the energy from the secondary to the user’s service-entrance equipment. Figures 18-1 and 18-2 depict the component parts of a typicca distribution system. Distribution investment constitutes 50% of the capital investment of a typical electric utility systeem Recent trends away from generation expansion at many utilities have put increased emphasis on distribution system development. The function of distribution is to receive electric power from large, bulk sources and to distribute it to consumers at voltage levels and with degrees of reliability that are appropriate to the various types of users. For single-phase residential users, American National Standard Institute (ANSI) C84.1-1989 defines Voltage Range A as 114/228 V to 126/252 V at the user’s service entrance and 110/220 V to 126/252 V at the point of utilization. This allows for voltage drop in the consumer’s system. Nominal voltage is 120/240 V. Within Range A utilization voltage, utilization equipment is designed and rated to give fully satisfactory performance. As a practical matter, voltages above and below Range A do occur occasionally; however, ANSI C84.1 specifies that these conditions shall be limited in extent, frequency, and duration. When they do occur, corrective measures shall be undertaken within a reasonable time to improve voltages to meet Range A requirements. Rapid dips in voltage which cause incandescent-lamp “flicker” should be limited to 4% or 6% when they occur infrequently and 3% or 4% when they occur several times per hour. Frequent dips, such as those caused by elevators and industrial equipment, should be limited to 11/2% or 2%. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-3 FIGURE 18-2 One-line diagram of typical primary distribution feeder. Reliability of service can be described by factors such as frequency and duration of service interrupttions While short and infrequent interruptions may be tolerated by residential and small commerrcia users, even a short interruption can be costly in the case of many industrial processes and can be dangerous in the case of hospitals and public buildings. For such sensitive loads, special measuure are often taken to ensure an especially high level of reliability, such as redundancy in supply circuits and/or supply equipment. Certain computer loads may be sensitive not only to interruptions but even to severe voltage dips and may require special power-supply systems which are virtually uninterruptible. From a system-planning and design point of view, the optimal choice of subtransmission voltage and system arrangement is closely interrelated with distribution substation size and with the primary distribution voltage level. At any given time, the most economical arrangement is achieved when the sum of the subtransmission, substation, and primary feeder costs to serve an area is a minimum over Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-4 SECTION EIGHTEEN *From “Out of Sight, Out of Mind?,” January 2004, Edison Electric Institute (used with permission). the life of the facilities. In practice, the number, size, and availability of bulk supply sources for feediin the subtransmission may be significant factors as well. A distribution system should be designed so that anticipated load growth can be served at minimmu expense. This flexibility is needed to handle load growth in existing areas as well as load growth in new areas of development. Overhead and underground distribution systems are both used in large metropolitan areas. In the past in smaller towns and in the less-congested areas of larger cities, overhead distribution was almost universally used; the cost of underground distribution for residential areas was several times that of overhead. During the past 25 to 30 years, the cost of underground residential distribution (URD) has been reduced drastically through the development of low-cost, solid-dielectric cables suitable for direct burial, mass production of pad-mounted distribution transformers and accessories, mechanized cable-installation methods, etc. The cost of a typical URD system for a new residential subdivision is about 50% greater than that of an overhead system in many areas; in others, there is little or no differential due to local land conditions. As a result, some utilities will justifiably have some type of extra charge for underground. With the increased public interest in improving the appearance of residential areas and the declining cost of URD, the growth of URD has been extremely rapid. Today, perhaps as much as 70% of new residential construction is served undergroound A number of states have enacted legislation making underground distribution mandatory for new residential subdivisions. Undergrounding*. In the last decade, U.S. East Coast and Midwest regions experienced several catastrophic “100 year storms.” These storms left widespread electric power outages that lasted severra days. Given the critical role that electricity plays in our modern lifestyle, even a momentary power outage is an inconvenience. A days-long power outage presents a major hardship and can be catastrophic in terms of its health and safety consequences, and the economic losses it creates. Why then, don’t we bury more of our power lines so they will be protected from storms? The fact is we already are placing significant numbers of power lines underground. Over the past 10 years, approximately half of the capital expenditures by U.S. investor-owned utilities for new transmission and distribution wires have been for underground wires. Almost 80% of the nation’s electric grid, however, has been built with overhead power lines. Would electric reliability be improved if more of these existing overhead lines were placed underground as well? What the report finds is that burying existing overhead power lines does not completely protect consumers from storm-related power outages. However, underground power lines do result in fewer overall power outages, but the duration of power outages on underground systems tends to be longer than for overhead lines. Also, undergrounding is expensive, costing up to $1 million/mile or almost 10 times the cost of a new overhead power line. This means that most undergrounding projects cannno be economically justified and must cite intangible, unquantifiable benefits such as improved community or neighborhood aesthetics for their justification. Determining who pays and who benefiit from undergrounding projects can be difficult and often requires the establishment of separate government-sponsored programs for funding. How Much Does Undergrounding Improve Electric Reliability? Comparative reliability data indicate that the frequency of outages on underground systems can be substantially less than for overheea systems. However, when the duration of outages is compared, underground systems lose much of their advantage. The data show that the frequency of power outages on underground systems is only about one-third of that of overhead systems. A 2000 report issued by the Maryland Public Service Commission concluded that the impact of undergrounding on reliability was “unclear.” In a 2003 study, the North Carolina Commission summarized 5 years of underground and overheea reliability comparisons for North Carolina’s investor-owned electric utilities–Dominion North Carolina Power, Duke Energy, and Progress Energy Carolinas. The data indicate that the frequency of outages on underground systems was 50% less than for overhead systems, but the average duration of an underground outage was 58% longer than for an overhead outage. In other words, for Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-5 the North Carolina utilities, an underground system suffers only about half the number of outages of an overhead system, but those outages take 1.6 times longer to repair. Based on this data, Duke Power concluded, “Underground distribution lines will improve the potential for reduced outage interruption during normal weather, and limit the extent of damage to the electrical distribution systte from severe weather-related storms.” However, once an interruption has occurred, underground outages normally take significantly longer to repair than a similar overhead outage. Reliability Characteristics of Overhead and Underground Power Lines • Overhead lines tend to have more power outages primarily due to trees coming in contact with overhead lines. • It is relatively easy to locate a fault on an overhead line and repair it. A single line worker, for example, can locate and replace a blown fuse. This results in shorter duration outages. • Underground lines require specialized equipment and crews to locate a fault, a separate crew with heavy equipment to dig up a line, and a specialized crew to repair the fault. This greatly increases the cost and the time to repair a fault on an underground system. • In urban areas, underground lines are 4 times more costly to maintain than overhead facilities. • Underground lines have a higher failure rate initially due to dig-ins and installation problems. After 3 or 4 years, however, events that affect failures become virtually nonexistent. • As underground cables approach their end of life, failure rates increase significantly and these failures are extremely difficult to locate and repair. Maryland utilities report that their underground cables are becoming unreliable after 15 to 20 years and reaching their end of life after 25 to 35 years. • Pepco found that customers served by 40-year-old overhead lines had better reliability than custommer served by 20-year-old underground lines. • Two Maryland utilities have replaced underground distribution systems with overhead systems to improve reliability. • Water and moisture infiltration can cause significant failures in underground systems when they are flooded, as often happens in hurricanes. • Due to cost or technical considerations, it is unlikely that 100% of the circuit from the substation to the customer can be placed entirely underground. This leaves the circuit vulnerable to the same types of events that impact other overhead lines, for example, high winds and ice storms. Other Benefits of Undergrounding. One of the most commonly cited benefits of undergrounding is the removal of unsightly poles and wires. Local communities and neighborhoods routinely spend millions to place their existing overhead power lines underground. Similarly, when given the option, builders of new residential communities will often pay a premiiu of several thousand dollars/home to place the utilities underground. These “aesthetic” benefits are virtually impossible to quantify, but are, in many instances, the primary justification for projects to place existing power lines underground. Underground lines do have other benefits. In 1998, Australia completed a major benefit/cost analysis of undergrounding all existing power lines in urban and suburban areas throughout the countrry The study costed more than $1.5 million Australian ($1.05 million U.S. at current rates), and repressent what may be the most comprehensive undertaking to date to quantify the benefits and costs related to undergrounding. In addition to the value of improved aesthetics, the study identified the following potential benefiit related to undergrounding that it attempted to quantify: • Reduced motor vehicle accidents caused by collisions with poles • Reduced losses caused by electricity outages • Reduced network maintenance costs • Reduced tree-pruning costs Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-6 SECTION EIGHTEEN • Increased property values • Reduced transmission losses due to the use of larger conductors • Reduced greenhouse-gas emissions (lower transmission losses) • Reduced electrocutions • Reduced brushfire risks, and • Indirect effects on the economy such as employment Of this list, the only four items deemed significant in the study’s benefit/cost calculations included: • Motor vehicle accidents • Maintenance costs • Tree-trimming costs, and • Line losses The Australian list of benefits does not include improved reliability as a significant benefit of undergrounding. Instead it identifies the reduction in losses from motor vehicle accidents as the largest benefit from undergrounding—something utilities have no control over. Underground cost data for U.S. utilities indicate that the cost of placing overhead power lines underground is 5 to 10 times the cost of new overhead power lines. Other factors also can result in substantial additional customer costs for undergrounding projects. These include: • Electric undergrounding strands other utilities, for example, cable and telephone companies, which must assume 100% of pole costs if electric lines are underground. These additional nonelectric costs will likely be passed on to cable and telephone consumers. • Customers may incur substantial additional costs to connect homes to newly installed underground service, possibly as much as $2000 if the household electric service must be upgraded to conform to current electric codes. Paying for Undergrounding. In spite of its high cost and lack of economic justification, undergrouundin is very popular across the country. In 9 out of 10 new subdivisions, contractors bury power lines. In addition, dozens of cities have developed comprehensive plans to bury or relocate utility lines to improve aesthetics. For new residential construction, utilities vary on how they charge for the cost of providing underground services. When it comes to converting existing overhead lines to underground, a varieet of programs are being utilized. They include special assessment areas, undergrounding districts, and state and local government initiatives. Placing existing power lines underground is expensive, costing approximately $1 million/mile. This is almost 10 times the cost of a new overhead power line. While communities and individuals continue to push for undergrounding—particularly after extended power outages caused by major storms—the reliability benefits that would result are uncertaain and there appears to be little economic justification for paying the required premiums. Indeed, in its study of the undergrounding issue, the Maryland Public Service Commission concluuded “If a 10 percent return is imputed to the great amounts of capital freed up by building overheea instead of underground lines, the earnings alone will pay for substantial ongoing overhead maintenance,” implying that utilities could have more resources available to them to perform maintennanc and improve reliability on overhead lines if they invested less in new underground facilities. For the foreseeable future, however, it appears that the undergrounding of existing overhead power lines will continue, justified primarily by aesthetic considerations—not reliability or economic benefiits Many consumers simply want their power lines placed underground, regardless of the costs. The challenge for decision makers is determining who will pay for these projects and who will benefit. There are several undergrounding programs around the country that are working through these equity issues and coming up with what appear to be viable compromises. Once a public-policy Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-7 decision is reached to pursue an undergrounding project, it is worthwhile for the leaders involved to evaluate these programs in more detail to determine what is working, and what is not. Rural Service. Rural service has been extended to most farmers and rural dwellers through the efforts of utilities, cooperatives, and government agencies. Rural construction must be of the least-expensive type consistent with durability and reliability because there may be only a few users per mile of line. Historically, rural construction has been overhead, but the advent of cable-plowing techniques has made underground economically competitive with overhead in some parts of the country, and a growing amount of rural distribution is being installed underground. Higher primary voltages of 24.9Y/14.4 and 34.5Y/19.92 kV are continuing to grow in usage, although primary voltages in the 15-kV class predominate. The 5-kV class continues to decline in usage. Surveys indicate that in recent years approximately 78% of the overhead and underground line additions are at 15 kV, 11% are at 25 kV, and 7.5% are at 35 kV. Generally, when a higher distribution voltage is initiated, it is built in new, rapidly growing load areas. The economic advantage of the higher voltages usually is not great enough to justify massive conversions of existing lower-voltage facilities to the higher level. The lower-voltage areas are contained and gradually compressed over a period of years as determined by economics, obsolescence, and convenience. Virtually, all modern primary systems serving residential and small commercial and small industrial loads are 4-wire, multigrounded, common-neutral systems. 18.2 DISTRIBUTION-SYSTEM AUTOMATION Distribution automation (DA), a system to monitor and control the distribution system in real-time, was gradually introduced in the 1970s more as a concept than a fully developed plan. Unlike the introduction of EMS, where utilities readily saw the benefits of automatic generation control and economic dispatch and adopted the technology, utilities were much more cautious in their approach to distribution automation. Early distribution automation projects were undertaken by a handful of utilities. The technology was changing and evolving so much so that DA was being touted as an amorphous system capable of covering any imaginable function under the sun. A 1984 EPRI project, Guidelines for Evaluating Distribution Automation, focused attention on what functions could be automated and what value could be attached to those functions. A positive result of this project is that it got people thinking about what functions mattered most. However, it was a little bit ahead of its time in that there wasn’t much standardization in systems employed for DA and one couldn’t simply select functions of interees and expect to obtain a system that could be built for the total value of the functions selected. Then too, the choice of the communications systems (e.g., telephone, fiber optics, radio, carrier, etc.) proved to be a barrier to widespread implementation. At the substation level, equipment loadings became an early focus, and asset management became a desired function for DA systems. In addition, the ability to trip distribution circuit breakers and transfer load between substations was commonplace as SCADA was added and this represented the extent of distribution automation to many companies. Volt/var control, that is, controlling the combination of load tap changers (LTC) or voltage regulattor and switched capacitor banks within a substation, was a function many companies incorporaate with DA. With adoption of microprocessor relays and fault distance relaying, some incorporated the output information from fault distance relays and diagnostic alarms from various subsystems to be part of the DA package. Moving outside the substation, controlling automated circuit tie switches was prompted by reliabiilit considerations. Having SCADA links to other reclosers, particularly the ones with microproccesso controls, enabled more ability to remotely control field switching and achieve more rapid restoration of service. Distribution automation is still evolving with systems incorporating many of the functions previouusl described. More utilities are employing varying degrees of distribution automation and more standardization is taking place. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-8 SECTION EIGHTEEN 18.3 CLASSIFICATION AND APPLICATION OF DISTRIBUTION SYSTEMS Distribution systems may be classified in according to: • voltage—120 V, 12,470 V, 34,500 V, etc. • scheme of connection—radial, loop, network, multiple, and series. • loads—residential, small light and power, large light and power, street lighting, railways, etc. • number of conductors—2-wire, 3-wire, 4-wire, etc. • type of construction—overhead or underground. • number of phases—single-phase, 2-phase, or 3-phase; and as to frequency: 25 Hz, 60 Hz, etc. Application of Systems. In American practice, alternating-current (ac) 60-Hz systems are almost universally used for electric power distribution. These systems comprise the most economical method of power distribution, owing in large measure to the ease of transforming voltages to levels appropriate to the various parts of the system. These transformations are accomplished by means of reliable and economical transformers. By proper system design and the application of overvoltage and overcurrent protective equipment, voltage levels and service reliability can be matched to almost any consumer requirement. Single-phase residential loads generally are supplied by simple radial systems at 120/240 V. The ultimate in service reliability is provided in densely loaded business/commercial areas by means of grid-type secondary-network systems at 208Y/120 V or by “spot” networks, usually at 480Y/277 V. Secondary-network systems are used in about 90% of the cities in this country having a population of 100,000 or more and in more than one-third of all cities with populations between 25,000 and 100,000. Where secondary-network systems do not supply sufficiently reliable service for critical loads, emergency generators and/or batteries are sometimes provided together with automatic switching equipment so that service can be maintained to the critical loads in the event that the normal utility supppl is interrupted. Such loads are found in hospitals, computer centers, key industrial processes, etc. Single-phase residential loads are almost universally supplied through 120/240-V, 3-wire, singlephhas services. Large appliances, such as ranges, water heaters, and clothes dryers, are served at 240 V. Lighting, small appliances, and convenience outlets are supplied at 120 V. An exception to the preceding comments occurs when the dwelling unit is in a distributed secondary-network area served at 280Y/120 V. In this case, large appliances are supplied at 208 V and small appliances at 120 V. Three-phase, 4-wire, multigrounded, common-neutral primary systems, such as 12.47Y/7.2 kV, 24.9Y/14.4 kV, and 34.5Y/19.92 kV, are used almost exclusively. The fourth wire of these Y-connected systems is the neutral for both the primary and the secondary systems. It is grounded at many locatioons Single-phase loads are served by distribution transformers, the primary windings of which are connected between a phase conductor and the neutral. Three-phase loads can be supplied by 3-phase distribution transformers or by single-phase transformers connected to form a 3-phase bank. Primary systems in the 15-kV class are most commonly used, but the higher voltages are gaining acceptance. Figure 18-2 illustrates a typical radial primary feeder. The 4-wire system is particularly economic for URD systems because each primary lateral or branch circuit consists of only one insulated phase conductor and the bare, uninsulated neutral rather than two insulated conductors. Also, only one primary fuse is required at each transformer and one surge arrester in overhead installations. Three-phase, 3-wire primary systems are not widely used for public distribution, except in California. They can be used to supply single-phase loads by means of distribution transformers having primary winding connected between two phase conductors. Single-phase primary laterals consist of two insulated phase conductors; each single-phase distribution transformer requires two fuses and two surge arresters (where used). Three-phase loads are served through 3-phase distribution transforrmer or appropriate 3-phase banks. Two-phase systems are rarely used today. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-9 18.4 CALCULATION OF VOLTAGE REGULATION AND I2R LOSS When a circuit supplies current to a load, it experiences a drop in voltage and a dissipation of energy in the form of heat. In dc circuits, voltage drop is equal to current in amperes multiplied by the resistaanc of the conductors, V IR. In ac circuits, voltage drop is a function of load current and power factor and the resistance and reactance of the conductors. Heating is caused by conductor losses; for both dc and ac circuits they are computed as the square of current multiplied by conductor resistance in ohms. Watts I2R, or kW I2R/1000. Capacitance can usually be neglected for calculation in distribution circuits because its effect on voltage drop is negligible for the circuit lengths and operattin voltages used. In circuit design, a conductor size should be selected so that it will carry the required load within specified voltage-drop limits and will have an optimized value of installed cost and cost of losses. Today, a conductor size meeting these criteria will operate well within safe operattin temperature limits. In some cases, short-circuit current requirements will dictate the minimum conductor size. Percent voltage drop or percent regulation is the ratio of voltage drop in a circuit to voltage deliverre by the circuit, multiplied by 100 to convert to percent. For example, if the drop between a transforrme and the last customer is 10 V and the voltage delivered to the customer is 240, the percent voltage drop is 10/240 100 4.17%. Often the nominal or rated voltage is used as the denominaato because the exact value of delivered voltage is seldom known. Percent I2R or percent conductor loss of a circuit is the ratio of the circuit I2R or conductor loss, in kilowatts, to the kilowatts delivered by the circuit (multiplied by 100 to convert to percent). For example, assume a 240-V single-phase circuit consisting of 1000 ft of two No. 4/0 copper cables supplies a load of 100 A at unity power factor. Direct-current voltage drop is easily calculated by multiplying load amperes I by ohmic resistaanc R of the conductors through which the current flows (see Sec. 4 for ohmic resistance of varioou conductors). Example: A 500-ft dc circuit of two 4/0 copper cables carries 200 A. What is the voltage drop? Resistance of 1000 ft of 4/0 copper cable is 0.0512 . If 240 is the delivered voltage, I2R or conductor loss in dc or ac circuits is calculated by multiplying the square of the current in amperes by ohmic resistance of the conductors through which the current flows. The result is in watts. In dc circuits, percent voltage drop and percent conductor loss are identical. In ac circuits, the ratio of percent conductor loss to percent voltage regulation is given approximately by the following approximate formula: (18-1) where power-factor angle and impedance angle; that is, tan X/R. % I 2R loss % voltage drop cos f cos u cos (f u) % I2R I2R/VI 100 IR/V 100 % voltage drop IR/V 100 % regulation 10.24/240 100 4.26% Drop IR 200 0.0512 10.24 V % I2R loss 1.024/24 100 4.26% Load delivered 240 100 24,000 W 24 kW I2R 1002 2 0.0512 1024 W 1.024 kW Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-10 SECTION EIGHTEEN TABLE 18-1 Voltage Drop in Volts per 100,000 A ⋅ ft, 2-Wire DC Circuits (Loop) Conductor size, AWG or kcmil Approx. equivalent Copper aluminum 6 4 102.8 4 2 64.6 2 1/0 40.7 1/0 3/0 25.6 2/0 4/0 20.3 4/0 336 12.8 350 556 7.71 500 795 5.39 1000 2.70 1500 1.80 2000 1.35 Note: 1 ft 0.3048 m. Volts drop per 100,000 A ⋅ ft, 90º copper temp Table 18-1 gives voltage drop in volts per 100,000 A ⋅ ft for 2-wire dc circuits for a number of conductor sizes. Ampere-feet is the product of the number of amperes of current flowing and the distaanc in feet between the sending and receiving terminals multiplied by 2 to take into account the drop in both the outgoing and return conductors. Or the feet can be considered to be the total numbbe of conductor feet, outgoing and return. Table 18-1 also gives the voltage drop for 3-wire circuits when serving balanced loads, where the term “feet” is taken to mean twice the number of feet between sending and receiving terminals. Example 1. What is the voltage drop and percent voltage drop when 200 A dc flows 1500 ft one way through a 2-wire, 120-V, 556-kcmil aluminum circuit? First determine ampere-feet factor as 100 1500/100,000 1.5. From Table 18-1, the voltage drop is 7.71 V per 100,000 A ⋅ ft. This value multiplied by the 1.5 factor gives the total voltage drop 1.5 7.71 11.6 V. The percent voltage drop 11.6 100/120 9.64%. The percent conductor loss also is 9.64%, which is equivalent to 120 100 0.0954 1.16 kW. Example 2. A mine 1 mile from a motor-generator station must receive 100 kW dc at not less than 575 V. Maximum voltage of the generator is 600 V. What conductor size should be used? 18.36 voltage drop per 100,000 A ⋅ ft from Table 18-1 25 V Therefore, voltage drop per 100,000 A ⋅ ft 25/18.36 1.36. From Table 18-1, the copper conduccto size corresponding to 1.36 V/100,000 A ⋅ ft is 2000 kcmil copper. Calculating Voltage Drop in AC Circuits. The voltage drop per mile in each round wire of 3-phase 60-Hz line with equilateral spacing D inches between centers or in each wire of a single-phase line D inches between centers is (18-2) V~ drop I~R jI~ a0.2794 log Dr0.03034 mb volts in phasor form A # ft 100,000 173.9 10,560 100,000 18.36 Loop ft 2 5280 10,560 ft Max. current 100,000 W 575 V 173.9 A Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-11 where is in phasor amperes, R is the 60-Hz resistance of the wire per mile, , log is the log to base 10, r is the radius of round wire, in, and µ is the permeability of the wire (unity for nonmagneeti materials such as copper or aluminum). j in Eq. (18-2) denotes an angle of 90; j means 90leading, j means 90lagging. Thus, the expression for phasor current lagging the reference voltaag is with reference to a conveniently chosen horizontal axis of reference—usualll sending-or receiving-end voltage. The symbol over I or V indicates phasor values. Voltage drops determined in this manner are also phasors and are with respect to the reference axis. When wire is stranded, an equivalent radius must be used for r in Eq. (18-2). r 0.528 for 7 strands, r 0.5585 for 19 strands, r 0.5675 for 37 strands, where r equivalent radius, in, and A area of metal, in2. Frequency is 60 Hz for the constants in parentheses in Eq. (18-2), which gives reactance X in ohms per mile. For 25 Hz, multiply by 25/60. The equation is sometimes written (18-3) where I is in phasor amperes and Z Z/⋅ /mi at 60 Hz. Three unsymmetrically spaced wires a, b, and c of a 3-phase circuit with correct transpositions can have voltage drop in each wire calculated by Eq. (18-2) by substituting for D the geometric mean of the three interaxial distances: The Phasor Method. In Eq. (18-3), I is in vector amperes, where is the angle that the current lags (or leads) the voltage. The sending-end voltage is usually chosen as the axis, or phasor, of reference in drawing the phasor diagram. For example, consider Fig. 18-3, where sending voltage , load current II , circuit impedance Z R jX, and load voltage (all phasors). The symbol is used for positive angles, assumiin that the counterclockwise direction from the phasor or reference is positive and the clockwise directions negative. Assume that Vs 230/0, 50 , 0.2 , and R jX. Thus 0.2 230 10 230 10 cos 34.70j 10 sin 34.70230 8.22 j 5.69 221.78 j 5.69 221.78 (very nearly) Neglecting the term j 5.69 simplifies the final calculation and gives the load voltage within a fraction of 1% of the precise result. This method is sufficiently accurate for practically all distributiio engineering calculations and can be thought of as (18-4) V drop IR cos u IX sin u IZ cos (f u) >34.70>u>71.57>36.87V ~L 230/050 Z~ >71.57Z~ >36.87I~ lV~L V ~s I~Z~ >uZ ~ >u>uVs Vs I~ Ix jIy Ilu D 23DabDbcDca V ~ drop per mile I~ (R jX) I~Z ~ volts in phasor form !A !A !A I~ Ix jIy I!uI~ FIGURE 18-3 Phasor diagram showing voltage relationships. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-12 SECTION EIGHTEEN where I and Z are absolute magnitudes, not phasor quantities, is the impedance angle, and is the power-factor angle by which the current lags (or leads) the voltage. Calculating the drop in the above example by this method: or Impedance Z can be visualized as the hypotenuse of a right triangle in which the base is the resistance R and the altitude is the reactance X. In phasor form, ˜ZR jX, where the positive sign is used for inductive reactance and the negative sign for capacitive reactance. Impedance also can be expressed as ˜ZZ , where Z is the absolute magnitude and is the angle between ˜Zand R in Fig. 18-4. This angle is an absolute value in that it has no relationship to the axis of reference in a phasor diagram, as do voltage and current. Alternating current causes a voltage drop in resistance which is in time phase with the current and in inductive reactance a drop which leads the current by 90 electrical degrees, assuming the positive direction for measurement of angles is counterclockkwise Or conversely, the current in an inductive reactance lags the voltage drop by 90. Impedance Values. Tables are available which give 60-Hz impedance values in ohms per 1000 ft for commmo sizes of wire and cable. The values can be expressed in the form ˜ZR jX, which can be converted to the form Z if desired. The latter form is convenient to use in voltage-drop calculations when the current is expressed as I . Power Factor. In typical distribution loads, the current lags the voltage, as shown in Fig. 18-3, where is shown as the angle between current and sending voltage and cos is referred to as the power factor of the circuit. In a purely resistive circuit, the curreen and voltage are in phase; consequently, the power factor is 1.0 or unity. In a purely inductive circuit, the voltage and current are out of phase by 90 electrical degrees, resulting in a power factor of zero. In a circuit consisting of a resistance in series with a reactance of equal ohmic value (45), 45also. Thus, the power factor is cos 450.707, or 70.7%. In a single-phase ac circuit, the load in kW can be expressed as kW EI cos (18-5) where Emagnitude of rms line-to-neutral voltage, kV Imagnitude of current, rms amperes electrical angle between phasor voltage and current >f>f>f10 cos (34.7) 10 0.822 8.22 V V drop IZ cos (f u) 50 0.2 cos (71.5736.87) 2.53 5.69 8.22 V 50 0.2 sin 71.57sin 36.87V drop 50 0.2 cos 71.57cos 36.87FIGURE 18-4 Impedance diagrams for series connection of resistance and reactance (L inductance, in henrys; C capacitance, in farads; F frequency, in hertz). Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-13 From Eq. (18-5), it is obvious that the magnitude of the current for a given voltage and kilowatt load depends on the power factor, or I kW/(E cos ) (18-6) The corresponding equations for balanced 3-phase circuits are kW EI cos (18-7) and I kW/( E cos ) (18-8) where the symbols are as specified above, and is measured as the angle between the line-toneuutra voltage of a given phase and the current in that phase. Example. Given a load of 500 kW at 80% power factor (lagging), 7.2 kV circuit voltage, 60-Hz, single-phase circuit using 1/0 aluminum conductor spaced 30 in on centers. The load is located 1 mi from the substation. What is the voltage drop? From tables on conductor characteristics, r 0.185 /1000 ft x 0.124 /1000 ft Therefore, R jX 5.28 (0.185 j 0.124) 0.9769 j 0.6547 From Eq. (18-6), E 7.2 cos 0.80 36.87and sin 0.60 From Eq. (18-4),* Calculation of 3-Phase Line Drops with Balanced Loads. In 3-phase circuits with balanced loads on each phase, the line-to-neutral voltage drop is merely the product of the phase current and the conduccto impedance as determined from standard tables. There is no return current with balanced 3-phase loads. Thus, the line-to-line voltage drop is times the line-to-neutral drop, or (18-9) Vdrop LL 23(IR cos u IX sin u) !3 2(67.84 34.10) 203.88 V Voltage drop 2(IR cos u IX sin u) (86.81 0.9769 0.8 86.81 0.6547 0.6) >uI kW E cos u 500 7.2 0.8 86.81 A !3 !3 *The factor of 2 is used for a single-phase system to represent the impedance of the outgoing conductor and the return conductor. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-14 SECTION EIGHTEEN For example, assume that the circuit of the preceding example now is a 3-phase 12.47-kV circuit 1 mi long with the same 1/0 aluminum conductors at an equivalent spacing of 30 in and a load of 3 500 1500 kW at 0.8 pf lagging. What is the line-to-line voltage drop? R and X are the same values as previously; that is, R jX 0.9769 j 0.6547 . The current per phase from Eq. (18-7) is as before, Calculation of Voltage Drop in Unbalanced Unsymmetrical Circuits. If there are n different wires a, b, c, d, ⋅ ⋅ ⋅ , n carrying currents Ia, Ib, Ic, ⋅ ⋅ ⋅ , In, respectively, whether 2-, 3-phase, the voltage drop in wire a per mile at 60 Hz is (18-10) where currents are in phasor amperes, Ra is 60-Hz ohmic resistance of conductor a per mile, r is equivalent radius, in inches, of conductor a, Dab, Dac, and Dan are distances, in inches, between centeer of conductors a and b, a and c, and a and n, and u is the permeability of conductor a (unity for nonmagnetic material). To get the drop in b, replace all a’s by b’s and all b’s by a’s in Eq. (18-10); similarly, to get the drop in c, interchange a’s and c’s; likewise for n. For 25 Hz, multiply that part of Eq. (18-10) which is in brackets by 25/60. Equation (18-10) gives voltage drop for any degree of load unbalance, power factor, or conductor arrangements. In using this formula, calculations are made easier by choosing voltage to neutral as the reference axis. Approximate Method of Calculating Voltage Drop in Unbalanced, Unsymmetrical Circuits. Equation (18-10) requires laborious calculations and is used only when exact results are necessary. Voltage drops sufficiently accurate for engineering purposes can be calculated by using an equivaleen impedance for each conductor. The reactance component of the equivalent impedance is compuute from a spacing D equal to the geometric means of the interaxial distances of the other conductors to the conductor being considered. For instance, if there are four conductors a, b, c, and n for conductor a, ; for conductor b, . Phasor and Connection Diagrams. Phasor and connection diagrams are drawn in computing voltaag drops in unbalanced circuits. Figure 18-5 shows an unbalanced 4-wire 3-phase 4160Y/2400-V circuit with assumed loads, power factors, and equivalent line impedances. Phase-to-neutral drops between source and load are given by the following, using one of the many possible voltage-notation conventions: Vna VnaIaZa InZn Vnb VnbIbZb InZn (18-11) Vnc VncIcZc InZn D 23 Dab, Dbc, Dbn D 23 Dab, Dac, Dan In log 1 Danb 0.03034 m Ia d volts in phasor form IaRa j c0.2794 aIa log 1rIb log 1 Dab Ic log 1 Dac . . . 117.51 59.06 176.57 V (approx.) 23 (86.81 0.9769 0.8 86.81 0.6547 0.6) Vdrop LL 23 (IR cos u IX sin u) I kW 23 E cos u 1500 23 12.47 0.8 86.81 A Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-15 FIGURE 18-5 Connections and phasor diagrams for unbalanced loads and unsymmetrical circuit. Phase-to-phase drops between source and load are given by the following: Vba VbaIaZa IbZb Vac VacIcZc IaZa (18-12) Vcb VcbIbZb IcZc In computing line-to-neutral drop in phase a, it is convenient to choose Vna as the axis of reference. Vna VnaIaZa InZn (100 )(1.2 ) X(43.2 )(0.5 ) 120 21.6 126.4 j61.9 Load voltage Vna2400 126.4 j61.9 2273.6 V (very nearly) Likewise, in computing line-to-neutral drop in phase b, it is convenient to choose Vnb as the axis of reference. The phasor diagram of Fig. 18-5 must be rotated in a counterclockwise direction 120; then Ib 90 and In 43.2 . Vnb VnbIbZb InZn (90 (1.1 ) (43.2 )(0.5 ) 65.8 j76.6 Load voltage Vnb2400 65.8 – j76.6 2334.2 V (very nearly) >40>87.8>47>10>87.8>10>7.8>29>40>32.2>49>20Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-16 SECTION EIGHTEEN Drop in the neutral conductor of a 4-wire 3-phase circuit or a 3-wire 2-phase circuit makes resultaan drop on the more heavily loaded phases greater than it would be for the same current under balannce conditions. Likewise, net drop is less on more lightly loaded phases than for the same current when balanced. Distributed Loads, Voltage Drop, and I2R Loss. Voltage drop and conductor power losses resulting from a concentrated load on a distribution line can be calculated easily as shown in earlier parts of this section. However, distribution circuit loads are generally considered to be distributed— often, but not always, uniformly. Distributed load may be considered as effectively concenttrate at one point along the circuit to calcullat total voltage drop and at another point to calculate conductor I2R losses in the conducctor If the load is uniformly distributed along the feeder, the total voltage drop can be calculated by assuming that the entire load is concentrated at the midpoint of the circuit, and the total I2R losses can be calculaate by assuming that the load is concentraate at a point one-third the total distance from the source. However, if there is a superimposed through load beyond the given feeder section, this method of calculation becomes cumbersoome It is possible to develop a single precise equivalent circuit for both the voltage-drop and loss calculations. Figure 18-6 shows the load representation and equivalent for uniforrml distributed loads. Equivalents also can be developed for other types of distribution. Figure 18-6 shows the equivalent circuit of two-thirds of the total load concentrated at three-quarters of the total distance from the source. 18.5 THE SUBTRANSMISSION SYSTEM Definition. Subtransmission is that part of the utility system which supplies distribution substatiion from bulk power sources, such as large transmission substations or generating stations. In turn, the distribution substations supply primary distribution systems. Subtransmission has many of the characteristics of both transmission and distribution in that it moves relatively large amounts of power from one point to another, like transmission, and at the same time it provides area coverage, like distribution. In some utility systems, transmission and subtransmission voltages are identical; in other systeems subtransmission is a separate and distinct voltage level (or levels). This is easy to account for because in the evolutionary development of utility systems, today’s transmission voltage naturally tends to become tomorrow’s subtransmission voltage, just as today’s subtransmission voltage tends to become tomorrow’s primary distribution voltage. Because of the wide range of voltages used in subtransmission, and because of the wide variation in geographic conditions and local ordinances, subtransmission circuits are sometimes built on pole lines on city streets, or on tower lines on private rights-of-way, or in underground cables. Voltages. Voltages of subtransmission circuits range from 12 to 345 kV, but today the levels of 69, 115, and 138 kV are most common. The use of the higher voltages is expanding rapidly as higher FIGURE 18-6 Uniformly distributed loads. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-17 primary voltages are receiving increased usage. Current practice as indicated by an informal utiliit survey is shown in Fig. 18-7; 115 and 138 kV together comprise about half the usage, 69 kV about 20%; 230 kV usage is becoming substantiial reflecting the growing use of 25-and 34.5-kV primary distribution. Conductors of ACSR or aluminum generally have supplanted copper in overhead constructiion and aluminum conductors are being used increasingly in cables. Voltage Regulation of Subtransmission. The size of conductors used in subtransmission systeem is determined by (1) magnitude and power factor of the load, (2) emergency loading requiremennts (3) distance that the load must be carried, (4) operating voltage, (5) permissible voltage drop under normal and emergency loading, and (6) optimal economic balance between installed cost of the conductor and cost of losses. Table 18-2 gives the line-to-neutral voltage drops per 100,000 A ft for common cable and overhead conductor sizes and representative power factors for 34.5-and 69-kV subtransmission. Values in the table are based on the approximate formula (18-4) Vdrop IR cos IX sin IZ cos () where R, X, and Z are 60-Hz resistance, reactance, and impedance in ohms per 1000 ft of a single conducctor is the power-factor angle in electrical degrees, and is the impedance angle, tan–1 (X/R). Examples of How to Use Table 18-2. Determine the voltage drop when a 3-phase 20,000-kVA load at 95% power factor is carried 10 mi over an overhead 69-kV circuit with No. 2/0 ACSR conductor. Assuming the receiving-end voltage to be 69 kV, the current is Circuit feet are 10 5280 52,800 ft Thus From the overhead portion of Table 18-2, the voltage drop per 100,000 A ft at 95% power factor for a No. 2/0 ACSR conductor is 19.1 V. Therefore, the total voltage drop for the example is 88.36 19.1 1687.68 V line-to-neutral. Since normal line-to-neutral voltage is 39.838 kV, or 39,838 V, the percent voltage drop is 1687.68 100/39,838 4.24%. Assuming that permissible voltage drop is the limiting factor, what overhead ACSR conductor size should be used to supply a load of 40,000 kVA at 95% power factor and receiving-end voltage of 69 kV with a permissible drop of 5% and 8 mi between sending and receiving ends? A# ft 100,000 334.71 42,240 100,000 141.38 Circuit feet 8 5280 42,240 ft Current 40,000 !3 69 334.71 A 69/!3 A# ft 100,000 167.35 52,800 100,000 88.36 I kVA !3E 20,000 !3 69 167.35 A FIGURE 18-7 Use of distribution substation highvolltag rating. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONTABLE 18-2 Voltage Drops per 100,000 A ⋅ ft* for 3-Phase, 60-Hz, 34.5-and 69-kV Subtransmission Voltage class Approx. amp. 34.5 kV 69 kV capacity for Lagging power factor air moving at Conductor size 0.7 0.8 0.9 0.95 1.00 0.7 0.8 0.9 0.95 1.00 2 ft/s Underground subtransmission† Aluminum: No. 1/0 18.3 19.9 21.1 21.5 21.0 No. 2/0 15.4 16.5 17.4 17.6 16.9 No. 4/0 10.7 11.2 11.5 11.4 10.5 350 kcmil 7.69 7.84 7.77 7.55 6.50 8.04 8.10 7.92 7.62 6.38 500 kcmil 6.15 6.12 5.88 5.59 4.50 6.53 6.43 6.10 5.74 4.48 750 kcmil 4.96 4.80 4.44 4.10 3.00 5.25 5.05 4.63 4.23 3.01 1000 kcmil 4.32 4.12 3.73 3.37 2.30 4.69 4.44 3.96 3.55 2.32 Overhead subtransmission‡ ACSR: No. 4 42.9 45.5 47.3 47.5 44.7 43.6 46.1 47.7 47.8 44.7 120 No. 2 31.5 32.5 32.7 32.1 28.4 32.2 33.1 33.1 32.4 28.4 165 No. 1/0 24.1 24.1 23.2 22.1 18.0 24.8 24.7 23.7 22.4 18.0 225 No. 2/0 21.6 21.2 20.1 18.8 14.6 22.3 21.8 20.5 19.1 14.6 260 No. 4/0 17.3 16.6 15.1 13.8 9.66 18.0 17.2 15.5 14.1 9.66 355 336.4 kcmil 12.7 11.8 10.4 9.13 5.57 13.4 12.4 10.8 9.44 5.57 480 477 kcmil 11.2 10.3 8.72 7.44 3.92 12.0 10.9 9.15 7.75 3.92 605 795 kcmil 9.73 8.68 7.06 5.78 2.37 10.4 9.28 7.49 6.09 2.37 850 Note: 1 in 25.4 mm; 1 in2 645 mm2; 1 ft 0.3048 m. Regulation of copper conductors can be estimated with reasonable accuracy as that of aluminum conductors two sizes larger. For ampacittie of cables, see Tables 18–22 and 18–23. *Values in the table give the difference in absolute value between sending-end and receiving-end line-to-neutral voltages of a balanced 3-phase circuit. †Underground cable impedances are based on 90C conductor temperature with close triangular spacing of cables using typical solid-dielectric insulation, 100% insulation level, single conductor, shielded and jacketed. ‡Overhead conductor impedances are based on 50C conductor temperature, ACSR construction, 600 A/in2 density with 60-in equivalent spacing for 35 kV and 90 in for 69 kV. 18-18 Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-19 The permissible voltage drop is V line-to-neutral. The corresponndin permissible voltage drop per 100,000 A ft is From Table 18-2 it is seen that this corresponds approximately to No. 4/0 ACSR. Subtransmission System Patterns. A wide variety of subtransmission system designs are in use, varying from simple radial systems to systems similar to networks. The radial system is not generally used because most utilities today plan their subtransmissiondistriibutio substation systems so that one major contingeenc such as outage of a subtransmission circuit or failure of a distribution substation transformer will not result in loss of load—or at least the loss of load will be of short duration while automatic switching operations take place. Thus, loop and multiple circuit patterns predominate. Figures 18-8 and 18-9 illustrate the basic nature of these two patterns. The loop pattern implies that a single circuit originating at one bulk power source “loops” through several substations before terminating at another bulk source or even at the originna source. Reinforcing ties, as indicated by the dotted connecttion are used when the number of substations exceeds some predetermined level. Multiple circuit pattern implies the use of two or more circuits which are tapped at each substation, as illustrated in Fig. 18-9. The circuits may be radial or may terminate in a second bulk power source. Many variatiion of the two basic patterns are found. From a recent informal survey of approximately 50 major utilities, it appears that the two patterns are about equally used. 1991.92 141.38 14.1 V/100,000 A # ft 0.05 69,000/!3 1991.92 FIGURE 18-8 Loop pattern. FIGURE 18-9 Multiple pattern. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-20 SECTION EIGHTEEN A vast majority of today’s subtransmission is of overhead construction, much of it built on city streets as contrasted with private rights of way. However, appearance and environmental consideratioons difficulty in obtaining substation sites and rights of way, and rapid growth of underground distribbutio are certain to exert continuing pressure on the undergrounding of subtransmission. Even with the use of direct-buried, solid-dielectric cables, the cost of underground subtransmission is many times the cost of overhead circuits, particularly where the overhead subtransmission can be built on city streets. Thus, a requirement to build future subtransmission underground would have major impact on the balance of overall subtransmission-substation-primary distribution costs. It undoubtedly would focus attention on minimizing the amount of subtransmission circuitry needed to cover the load area, which in turn would favor Fewer, larger substations Loop subtransmission pattern rather than multiple parallel circuits Depending on load density in this area, it could favor Higher primary voltage Higher subtransmission voltage Changes in either subtransmission or primary voltage levels are major decisions which require study in depth and ultimately the commitment of large financial resources. 18.6 PRIMARY DISTRIBUTION SYSTEMS The primary distribution system takes energy from the low-voltage bus of distribution substations and delivers it to the primary windings of distribution transformers. Overhead Primary Systems. Typically, overhead primary distribution systems have been operated as radial circuits (normally open loops) from the substation outward. Figure 18-2 shows schematicaall a typical primary feeder in a predominantly residential area; an overhead 12.47Y/7.2-kV systte is used for illustrative and functional purposes, but underground systems will be discussed later. The main feeder backbone usually is a 3-phase 4-wire circuit from which the single-phase lateral or branch circuits are tapped through fuse cutouts to protect the system from faults on the lateral circuiits The single-phase lateral circuits consist of one phase conductor and the neutral. Distribution transformers are connected between the phase and the neutral; in this case they would have a rating of 7200 V. Utilities use automatic reclosing feeder breakers and line reclosers to minimize service interruptioons However, serious problems involving the main will cause an outage to some or all of the feeder until line crews can locate the problem and manually operate pole-top disconnecting switches appropriaatel to isolate the problem and to pick up as much load as possible from adjacent feeders. Switches of this kind usually are found in both the main and lateral circuits, as indicated in Fig. 18-2. Also, it is often possible to make and to remove connections while the system is energized through the use of hot-line tools, hot-line clamps, insulated bucket trucks, etc. Generally, this approach has provided an acceptable level of service because overhead system troubles are relatively easy to locate, and repair times are short. However, when the entire primary system is installed underground, while the frequency of serious trouble is expected to be lower than in overhead systems, it is likely that the time involved in pinpointing the location and making repairs will be much longer than in overhead systems. Underground System. While a relatively small percentage of new general-purpose feeders is being installed totally underground, the trend is growing and is expected to continue to grow. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-21 Since it is difficult to accomplish many maintenance and operating functions on an underground system while it is “hot,” or energized, in contrast to overhead-system practices, specific provisions must be made in the system design to incorporate needed sectionalizing and overcurrent protectiiv equipment. The main feeder plan shown in Fig. 18-10 is reasonably typical of present practice on undergrooun systems supplying basically residential and small commercial loads. Note that the main feedeer are operated radially, but with normally open ties to adjacent main feeders. The main feeder switches usually are 3-phase, 600-A, manually operated load-break switches. The single-phase and 3-phase lateral circuits also are operated as normally open loops. Switching in the 200-A circuits can be accomplished by means of either load-break switches or separable, insulated cable connectors. Usually, two main feeder switches are grouped along with the lateral circuit switching and protective equipment into one piece of pad-mounted equipment. The primary feeders supplying secondary-network systems in metropolitan areas usually are radial 3-wire circuits consisting of 3/c cables in underground duct lines. The 3-phase network transforrmer are T-tapped to the primary feeders. Automation. With increasing emphasis on reliability of service, a definite trend is under way to make greater use of protective and sectionalizing equipment in the primary system in order to minimmiz the number of customers involved in an outage and to reduce the outage time. Proposed schemes run the gamut from manually operated devices to automatic devices remotely controlled from distribution centers. The remote-controlled schemes vary from some type of supervisory contrro to computer-controlled systems with built-in logic to cope quickly with the various problems which may arise. Primary-Distribution-System Voltage Levels. Since World War II, the 15-kV distribution class has become firmly entrenched and today represents 60% to 80% of all primary distribution activity. Very little expansion of lower-voltage systems is taking place. There is a trend, however, toward increasiin usage of primary voltage levels above the 15-kV class. This trend has an impact on substation and subtransmission practices as well because higher primary voltages almost axiomatically lead to larger substations and higher subtransmission voltages. FIGURE 18-10 Typical main-feeder underground circuit. (All switches closed unless shown otherwise.) Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-22 SECTION EIGHTEEN The two principal voltages above 15 kV are 24.49Y/14.4 kV and 34.5Y/19.92 kV. New line additiion at these voltage levels now average more than 20% of those at 15 kV. To achieve economy, the higher primary voltages also require heavier feeder loadings which could imply reduced service reliability because more customers are affected by primary faults. Greater use of automatic switching and protective equipment can do much toward preserving a level of reliability to which the public has become accustomed. This is another reason that most observers believe that an increased amount of automation is inevitable in our distribution systems. For example, a typical 12.47-kV feeder serves a normal peak load on the order of 6000 to 7000 kVA. On this basis, the probable peak loading of a fully developed 34.5-kV feeder would be expected to be in the neighborhood of 18,000 to 20,000 kVA. Why go to high-voltage distribution (HVD)? Most of today’s systems in the 15-kV class are not voltage-drop-limited, and cost of higher-voltage laterals and associated equipment needed to cover the load area is greater. The major economic advantages are: 1. Larger (and fewer) substations 2. Fewer circuits 3. Possibility of eliminating a system voltage-transformation level where the new primary voltage is the former subtransmission level Other advantages of HVD which are difficult to evaluate in dollars are: 1. Reduced losses in early stages of development 2. Reduced voltage regulation 3. Greater distance or area coverage 4. Fewer circuits per route (reduced congestion) 5. Fewer circuit positions at substations 6. Fewer substation sites 7. Greater flexibility in supplying large spot loads Some of the disadvantages of HVD have been 1. Cost of equipment 2. Reliability due to increased exposure 3. Higher equipment failure rates 4. Operability Conductor Sizes. The conductor sizes used in overhead primaries generally range from No. 2 AWG to 795 kcmil. ACSR and aluminum conductors have almost entirely displaced copper for new construction. Aerial cable is used occasionally for primary conductors in special situations where clearances are too close for open-wire construction or where adequate tree trimming is not practical. The type of construction more frequently used consists of covered conductors (nonshielded) supported from the messenger by insulating spacers of plastic or ceramic material. The conductor insulation, usually a solid dielectric such as polyethylene, has a thickness of about 150 mils for a 15-kV class circuit and is capable of supporting momentary contacts with tree branches, birds, and animals without puncturing. This type of construction is commonly referred to as spacer cable. The conductor sizes most commonly used in underground primary distribution vary from No. 4 AWG to 1000 kcmil. Four-wire main feeders may employ 3-or 4-conductor cables, but singlecondducto concentric-neutral cables are more popular for this purpose. The latter usually employ crosslinked polyethylene insulation, and often have a concentric neutral of one-half or one-third of the main conductor cross-sectional area. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-23 The smaller-sized cables used in lateral circuits of URD systems are nearly always single-conductor, concentric-neutral, crosslinked polyethylene-insulated, and usually directly buried in the earth. Insulation thickness is on the order of 175 mils for 15-kV-class cables and 345 mils for 35-kV class with 100% insulation level. Stranded or solid aluminum conductors have virtually supplanted copper for new construction, except where existing duct sizes are restrictive. With the solid-dielectric construction, in order to limit voltage gradient at the surface of the conductor within acceptable limits, a minimum conductor size of No. 2 AWG is common for 15-kV-class cables, and No. 1/0 AWG for 35-kV class. Voltage Regulation of Primary Distribution. Table 18-3 can be used to determine the voltage drop of an existing circuit when the load data are known or to determine minimum conductor size required to meet a given voltage-drop limit. Data are given for various underground-cable and overheadcondducto configurations for 12.47 and 34.5 kV. Example. What is the voltage drop for a 34.5-kV overhead circuit 3 mi long using 4/0 alumiinu conductor and carrying a balanced 3-phase load of 15,000 kVA at 90% power factor: The curreen is 15,000/34.5 251 A. The circuit feet are 3 5280 15,840 ft. Thus A ⋅ ft/100,000 251 15,840/100,000 39.758. From Table 18-3, the appropriate voltage drop per 100,000 A ft is 14.0 V line-to-neutral. Therefore, the total voltage drop for the example is 39.758 14.0 556.6 V line-to-neutral Since normal line-to-neutral voltage is 34,500 19,920 V, the percent voltage drop is 556.6 100/19,920 2.79% Example. What is the minimum aluminum conductor size to carry 6000 kVA at 90% power factor of balanced 3-phase load over a 2-mi, 12.47Y/7.2-kV feeder with no more than a 3% voltage drop? Load current is 6000/12.47 277.8 A. Circuit feet 2 5280 10,560 ft. Thus The corresponding drop per 100,000 A ft is 216/29.34 7.36 V, line-to-neutral. From Table 18-3, this value falls between 477 and 795 kcmil, so that the latter size would be chosen. Loading. Loading of primary feeders varies greatly depending on primary voltage, load density, emergency loading requirements, etc. Typical peak loads on 15-kV class feeders are 6 to 7000 kVA. Peak loads on 25-and 35-kV class, fully developed feeders probably will be proportionally greater in the future, assuming that appropriate measures can be taken to maintain acceptable reliability of service. Voltage Drop. Voltage drop in the primary feeder is an important factor in system design; however, it is only one of the many voltage-drop considerations involved in determining the range of voltages delivered to the customers’ service entrances. American National Standard, “Voltage Ratings for Electric Power Systems and Equipment (60-Hz),” ANSI C84.1-1995 (R200), defines in detail the voltage ranges which should be observed. Outside the distribution substation, voltage drops occur in the primary system, the distribution transformer, the secondary system, the service drop, and in the users’ wiring systems as well. Remedial measures, such as voltage regulators and shunt capacitor banks, can be used to counteract or reduce the voltage drop due to load flow. A traditional rough rule of thumb has been to allow a voltage drop of about 3% in the primary of urban and suburban systems at time of peak load. Actually, with typical load densities and primary systems of 15-kV class or higher, it is very probable that economic system designs have a primary voltage drop smaller than 3%. Permissible voltage drop 0.03 12,470 23 216 V A# ft 100,000 277.8 10,560 100,000 29.34 !3 !3 !3 Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONTABLE 18-3 Line-to-Neutral Voltage Drops per 100,000 A ⋅ ft* for 12.47Y/7.2 and 34.5Y/19.92 kV and Balanced 3-Phase Loads Voltage class 12.47Y/7.2 kV 34.5Y/19.92 kV Lagging power factor Conductor size 0.7 0.8 0.9 0.95 1.00 0.7 0.8 0.9 0.95 1.00 Underground primary Aluminum: Concentric neutral—direct buried, cross-linked polyethylene, conductor 70C, neutral 60C, earth resistivity 90 ⋅ cm3, triplex configuration, full installation No. 1/0 17.1 18.5 19.8 20.2 19.8 17.6 19.0 20.1 20.4 19.8 No. 2/0 14.1 15.1 16.0 16.3 15.7 14.6 15.6 16.3 16.5 15.7 No. 4/0 9.82 10.4 10.7 10.7 9.96 10.3 10.8 11.0 10.9 9.95 350 kcmil 7.01 7.19 7.17 7.00 6.11 7.37 7.49 7.39 7.16 6.11 500 kcmil 5.66 5.69 5.55 5.31 4.40 6.04 6.00 5.76 5.47 4.40 750 kcmil 4.63 4.55 4.30 4.03 3.12 4.95 4.82 4.49 4.16 3.11 1000 kcmil 4.10 3.98 3.69 3.41 2.52 4.37 4.20 3.85 3.52 2.51 Single conductor shielded and jacked, cross-lined polyethylene, conductor 70C, unigrounded shield, triplex configuration, full insulation 350 kcmil 7.29 7.49 7.51 7.35 6.47 7.55 7.72 7.67 7.47 6.47 500 kcmil 5.78 5.82 5.67 5.45 4.54 6.08 6.07 5.86 5.58 4.54 750 kcmil 4.64 4.54 4.26 3.97 3.02 4.88 4.74 4.41 4.08 3.02 1000 kcmil 4.02 3.85 3.52 3.21 2.26 4.23 4.03 3.65 3.31 2.26 Overhead primary† No. 4 42.3 45.4 47.8 48.5 46.6 43.4 46.3 48.5 49.0 46.6 115 No. 2 29.8 31.2 32.0 31.9 29.3 30.9 32.2 32.7 32.4 29.3 160 No. 1/0 21.8 22.2 22.1 21.5 18.5 23.0 23.2 22.8 22.0 18.5 215 No. 2/0 19.0 19.1 18.6 17.8 14.7 20.1 20.0 19.3 18.3 14.7 250 No. 4/0 14.7 14.3 13.3 12.4 9.20 15.9 15.3 14.0 12.7 9.20 340 336.4 kcmil 11.8 11.2 9.97 8.91 5.80 13.0 12.1 10.7 9.41 5.80 465 477 kcmil 10.4 9.58 8.27 7.18 4.10 11.5 10.5 8.97 7.68 4.10 590 795 kcmil 8.22 7.92 6.52 5.40 2.40 9.96 8.88 7.22 5.90 2.40 820 Note: 1 in 25.4 mm; 1 ft 0.3048 m. For ampacities of cables, see Tables 18-23 and 18-24. Regulation of copper for overhead conductors can be estimated with reasonable accuracy the same as that of aluminum conductors two sizes larger. For single-phase overhead primaries, the voltage drop is approximately two times the 3-phase values given in the table. For underground single-phase primaries in concentric-neutral, direct-buried cables, see section on URD systems. Cables are 15-and 35-kV classes, respectively. *Values in the table give the difference in absolute value between sending-end and receiving-end line-to-neutral voltages of a balanced 3-phase circuit, in volts. †Overhead conductor impedances are based on 50C conductor temperature, aluminum conductor with 30-in equivalent spacing for 12.47Y kV and 60-in for 34.5Y kV. Approx. amp. capacity for air moving at 2 ft/s 18-24 Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-25 In rural systems which are typified by long lines and light load densities, primary voltage drops may be somewhat larger. This is offset somewhat by the absence of secondaries in serving individuua farms; however, the service drops often are longer than in urban systems. The design objective, of course, is to keep delivered voltage to all customers in an acceptable and satisfactory range. 18.7 THE COMMON-NEUTRAL SYSTEM The 4-wire, multigrounded, common-neutral distribution system now is used almost exclusively because of the economic and operating advantages it offers. Usually, the windings of the substation transformers serving the primary system are wye-connected, and the neutral point is solidly grounded. Occasionally, a small amount of impedance is connected between the transformer neutral and ground in order to limit line-to-ground short-circuit currents on the primary system to a predetermmine value. The neutral circuit must be a continuous metallic path along the primary routes of the feeder and to every user location. Where primary and secondary systems are both present, the same conductor is used as the “common” neutral for both systems. The neutral is grounded at each distribution transformer, at frequent intervals where no transformers are connected, and to metallic water pipes or driven grounds at each user’s service entrance. The neutral carries a portion of the unbalanced or residual load currents for both the primary and secondary systems. The remainder of this current flows in the earth and/or the water system. For typical conditions, it is estimated that about one-half the return current flows in the neutral conductor, although the division can vary widely depending on earth resistivity and the relative routing of the electric and water systems. Figure 18-11 is a schematic representation of a common-neutral system. Grounding of Neutral. Rules related to grounding on the utility system neutral are given in the National Electrical Safety Code (NESC), ANSI C2, and regulations governing the grounding of the neutral on users’ premises are stated in the National Electrical Code (NEC), NFPA 70. In brief, the secondary neutral is grounded at every service through a metallic water-piping system and through “made electrode grounds” such as other underground metal systems, building steel, or drivve ground electrodes. The increasing use of nonmetallic water piping and insulating couplings on metal water systems is requiring the use of other grounding means. The secondary neutral also is grounded at the distribution transformer, usually by means of driven grounds. Although it is often FIGURE 18-11 Common-neutral methods of distribution. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-26 SECTION EIGHTEEN general practice to install a metal butt plate or a wire butt wrap on poles to help in grounding the systte neutral and other equipment, the NESC requires two such devices to equal one made electrode; as a result, neither can be used to satisfy the NESC requirement for a direct earth ground with a made electrode at each transformer or other arrester location. The resistance to ground of a typical metallic water-piping system usually is less than 3 . When made electrode grounds are used, they should have a resistance of not more than 25 . Many utilitiie strive for lower values such as 5, 10, or 15 . Where there is no secondary neutral as such and no distribution transformers, the primary neutrra should be grounded at intervals of not less than 1000 ft. Many utilities require grounding at smaller spacing, such as 500 ft; to meet the NESC requirements for a multigrounded neutral, there must be a minimum of the equivalent of four made electrodes in each mile. In URD systems, the primary circuits usually are in direct-buried, concentric neutral cable, so that excellent grounding is obtained. The neutral must have a continuous metallic path between the substation and users’ services. No disconnecting devices should be installed in the common neutral. In no case should the earth or buried metallic-piping systems be used as the only path for the return of normal load current. Size of Primary Neutral. On single-phase primary circuits (phase and neutral), the neutral conduccto should be large enough to carry almost as much current as the phase conductor. Often the same neutral conductor size is used for both, or the neutral has “100%” conductivity. In 3-phase primary circuits carrying reasonably balanced load, the neutral conductor can be consideerabl smaller than the phase conductors; 50% conductivity is not uncommon; some utilities specify size of neutral conductor, such as No. 1/0 aluminum, regardless of the size of the phase wires. Secondary-system neutral conductors are often the same size as the phase conductors where open-wire construction is used. Where triplexed construction is used, the neutral frequently has a reduced cross section. 4-Wire vs. 3-Wire Systems. The 4-wire, common-neutral primary system has many advantages over 3-wire systems: 1. Single-phase branch circuits, or laterals, consist of one insulated phase conductor and the neutral, rather than two insulated phase conductors. The economic advantage is very great in underground systems. 2. On overhead systems, only one lightning arrester is required at each single-phase distribution transformer, rather than two. 3. Only one primary bushing or cable termination is needed on each single-phase distribution transforrmer rather than two. In the case of underground systems where the primary “loops through” each distribution transformer, two primary cable terminations or connectors are needed, rather than four. 4. Only one fuse or fuse cutout is needed in the primary of each single-phase distribution transforrmer Not only is this a substantial economic advantage, but a short circuit in the primary of the transformer is interrupted positively by the action of a single fuse, and primary voltage is therebb removed from the transformer. In the case of the 3-wire system with the distribution transforrme connected phase-to-phase, a second fuse must operate to remove primary voltage and the fault. There may be appreciable time between operation of the two fuses during which fault curreen continues to flow and abnormal voltages may be experienced by the user. 5. Single-phase primary lateral circuits can be protected by a single fuse cutout, rather than two. Line-to-ground short circuits are promptly cleared by operation of one fuse and voltage removed from the branch circuit. In a 3-wire system (assumed grounded at the substation), single-phase lateral protection, if used, would require two fuse cutouts; a line-to-ground fault would blow only one fuse, leaving all the distribution transformers on that circuit excited at only 58% of normal as long as the faulted phase remains grounded. Under these conditions users’ equipment would be exposed to abnormally low voltage. The ability to fuse lateral circuits contributes substantially to Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-27 reliability of service, since a major amount of the total circuit exposure comprises the primary laterals in residential areas. Common-Neutral and Telephone Circuits. Usually, no problems are encountered in the joint use of poles for overhead distribution circuits and telephone circuits, particularly when the telephone circuuit are in cable, as is now common practice. Also, in underground residential circuits, power cables and telephone cables often are installed in the same trench with no intentional physical separation of the power and communication facilities, that is, “random lay.” Where separate grounding electrodes are employed for supply and communication facilities at customer’s premises, the electrodes shall be bonded together with not less than No. 6 AWG copper wire. 18.8 VOLTAGE CONTROL System Voltage Levels and Voltage Ranges. Since about 1900, there have been several recommendaation for certain voltages as standard or preferred for primary and secondary distribution systeems as well as for higher-voltage systems. The latest listing of standard system voltages is American National Standards Institute (ANSI) Standard C84.1-1995(R200), “Voltage Ratings for Electric Power Systems and Equipment (60 Hz).” This standard was formulated by both utilities and manufacturers, and its recommendations are followed by both segments of the industry. Observance of this standard enables the utilities and manufacturers to work in harmony. In many states, ANSI C84 is the basis for rulings of the regulatory commission as far as voltage requirements are concerned. This standard designates certain standard nominal voltages, including 120/240 V single-phase, 480Y/277 V, 12,470Y/7200 V, as well as the higher primary voltages, 24,940Y/14,400 V and 34,500Y/19,920 V, and others. Using the nominal 120/240-V system as an example, the standard designates two different ranges of voltage, range A and range B. Range A service voltage specifies that a utility supply system be so designed and operated that most service voltages are within the limits specified, for example, 114/228 and 126/252 V. The occurrence of service voltages outside these limits is to be infrequent. With the typical voltage drops between the service entrance and the points of utilization, the utilizaatio equipment is designed and rated to give fully satisfactory performance within range A. Range B service voltage includes voltages above and below range A that necessarily result from practical design and operating conditions on supply or user systems. These conditions are limited in extent, frequency, and duration. When they occur, corrective measures should be undertaken within a reasonable time to improve voltages to meet range A requirements. Insofar as practicable, utilization equipment is designed to give acceptable performance within range B. The design and operating bogey of the utilities is to provide service voltage to all customers at all times within range A limits. Voltage Profiles. It is usually convenient to discuss distribution-feeder-voltage regulation in terms of voltage profiles of the feeder, because the voltages are everywhere different on the feeder. A profile is simply a graph of feeder-voltage magnitude versus location on the feeder. For a simple case of one load at the end of the feeder (assuming uniform conductoor) the one-line diagram and profile are as shown in Fig. 18-12. The profile is a straight line between source and the load, and the voltage regulation at any point between is proportional to the distance from the source. It may be, as shown by the dashed-line profile, that minimum load is not zero, in which case the voltage variation is less than the calculated FIGURE 18-12 Voltage profile for concentrated load. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-28 SECTION EIGHTEEN regulation, since regulation is usually calculated on the voltage difference between no-load and fulllooa conditions. If additional loads are distributed along the feeder, the profile becomes a broken line, and if the load is uniformly distributed, the profile becomes a smooth curve, as shown in Fig. 18-13. The shape of the profile is of less consequence than knowing the extremes, because there are generally customers connected at all points on the feeder, and no customer’s voltage should be too high or too low. Since most feeders neither supply a single load nor are uniformly loaded, it usualll is necessary to calculate the voltage profile on a piece-by-piece basis, representing the loads and feeder configurations as accurately as the situation warrants. In addition to the distribution-feeder-voltage profile, there is additional regulation in the distributtio transformer and its secondaries and services. This additional regulation can be added to the profile as shown in Fig. 18-14. For protection of the first customer on the feeder 0 from possible overvoltage, it is usual to assume only a partially loaded transformer rather than one at full load. It is now possible to establish a limiting band of voltage within which all customers must lie for satisfactory service, usually range A. In turn, this also will establish the maximum permissible difference between the full-load and light-load primary voltage. The problem of holding the right voltage at each customer location at all times may be visualized by referring to Fig. 18-15. FIGURE 18-14 Additional regulation due to transformer and secondary. FIGURE 18-15 Distribution circuit with voltage profiles at heavy and light loads. FIGURE 18-13 Voltage profile for distributed load. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-29 Voltage Control. As implied in Fig. 18-15, usually there is voltage control equipment in the substaatio consisting of load-tap changers on the power transformers or bus or feeder voltage regulators. This regulating equipment can control only the voltage level of the primary system. It can have no effect on the voltage spread between the first and last customers on the feeder. There are several procedures which can be taken to correct for increasing voltage drops as the load on the feeders grows; among them are capacitors and supplementary feeder-voltage-regulator installations. The effect of capacitor application is illustrated in Fig. 18-16, where the load is assumed to be uniformly distributed along the feeder, and a capacitor bank is installed as indicated. The capacitor produces a voltage rise because of its leading current flowing through the inductive reactance of the feeder. As is seen in the figure, this voltage rise increases linearly from zero at the substation to its maximum value at the capacitor location. Between the capacitor location and the remote end of the feeder, the rise due to the capacitor is at its maximum value. When the capacitor voltage-rise profile is combined with the original feeder profile, the resulting net profile is obtained. The capacitor has increased the voltage level all along the feeder, resulting also in a reduced voltage spread. In practical applications, the capacitor bank can be a permanently connected or “fixed” bank as shown or an automatically switched bank. The fixed bank is limited in size by the allowable voltage rise during light-load conditions, and therefore may not produce sufficient voltage rise during heavylooa conditions. It can be supplemented by additional switched capacitors which automatically switch on at heavy-load conditions and off again as the load decreases. The effect of applying a supplementary feeder-voltage regulator is shown in Fig. 18-17. Note that the regulator produces no voltage effect between the source and the regulator location and its entire boost effect is between the regulator location and the remote end of the feeder. A typical primary feeder serves distributed loads, as well as concentrated loads, and may also have shunt capacitors and supplementary voltage regulation, such that all these previous concepts must be employed in studying voltage conditions. Voltage Regulation. Voltage regulation in distribution substations usually is accomplished by individdua feeder-voltage regulators or by automatic load-tap-changing equipment in the substation transformers. Individual feeder-voltage regulators are advantageous where feeders of differing lengths and diverse load characteristics are supplied from the same substation bus. Automatic loadtaapchanging equipment in the power transformer provides voltage control on the substation bus, or group regulation, when feeder lengths and load characteristics are reasonably homogeneous. Voltage control is needed to compensate not only for the voltage regulation in the subtransmissiio system and substation transformer, which is measurable at the substation, but also for the voltaag regulation which occurs in the distribution transformers and in the primary and secondary systems beyond the substation. The latter portion of the overall system voltage regulation is a function FIGURE 18-16 Effect of shunt-capacitor application. FIGURE 18-17 Effect of supplementary voltage regulator. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONof the load flow and system impedances and cannot be measured directly at the substation. Therefore, the control systems of the voltage regulators or tap-changing equipment not only sense the voltage at the substation but also usually contain a “line-drop compensator” which simulates the voltage drop between the station and some point in the distribution system and controls the regulatiin equipment accordingly. Switched shunt capacitor banks sometimes are installed at the distributiio substation as part of the overall system voltage control. Feeder-Voltage Regulator. In the typical radial primary system, it is often necessary to regulate the voltage of each feeder separately by means of feeder-voltage regulators. These regulators may be of single-phase or 3-phase construction. The former are available in sizes from 25 to more than 400 kVA, the latter from 500 to 2000 kVA. For distribution-system application they are commonly available for voltages from 2.5 kV to 34.5 kV grd Y. Regulators commonly are capable of raising or lowering the voltage delivered to the feeder by 10% and normally are rated on this basis. Modern voltage regulators all are of the step-voltage type, which has completely supplanted the earlier induction-voltage regulators. The step-voltage regulator basically is an autotransformer which has numerous taps in the series winding. Taps are charged automatically under load by a switching mechanism which responds to a voltage-sensing control in order to maintain voltage as close as practiccabl to a predetermined level. The voltage-sensing control receives its inputs from potential and current transformers and provides control of system voltage level and bandwidth. In addition, it permiit selection of line-drop compensation and provides features such as operation counter, time-delay selection, test terminals, and control switch. Most feeder-voltage regulators are of the 32-step design. Since they usually operate over a range of voltage of 20%, the voltage change per step is 5/8%. If the full range of regulation of 10% is not required, the regulators can carry more than rated current. For example, operating with a range of 5%, 160% of rated current can be carried. Line-Drop Compensator. In simplified terms, the regulator voltage (local voltage) is stepped down by means of a potential transformer and fed to the control system, where it is compared with the desired and preset voltage level. If the actual voltage deviates from the preset level by more than 1/2 of the bandwidth, which also is preset by the operator, the tap-changing mechanism operates, after a preset time delay, to return the voltage within the preset band. From a practical point of view, the minimum bandwidth is twice the size of the voltage step, or 2 5/8% 1.25%. Maintaining a small bandwidth is important in reducing voltage variations and in making full use of the allowable system voltage drop. The line-drop compensator consists of adjustable resistance and reactance components and is presse to simulate system impedance. By means of a current transformer, current proportional to load current is circulated through the resistance and reactance, producing a voltage signal which is combiine with the signal from the local voltage. The net result is that the line-drop compensator causes a higher voltage to be held at the voltage regulator during periods of heavy load. In this way, a consttan voltage is held at some point in the system, as determined by the compensator setting. This helps to achieve the goal of minimizing the voltage change with varying loads at any location. Supplementary Voltage Regulation. In some long primary circuits, such as rural feeders, it is often necessary to provide voltage regulation in addition to that incorporated in substation equipment because of large voltage drops in the system. This supplementary voltage regulation usually is improved by single-phase automatic step regulators in the smaller ratings. These regulators are suitabbl for pole mounting. Bus Regulation. Bus regulation at the distribution substation usually is provided by automatic loadtaapchanging equipment built into the substation transformer or by large step-voltage regulators. Switched Shunt Capacitors. Switched shunt capacitors are often applied at distribution substations or out on the primary feeders to accomplish a portion of the overall voltage-regulation job. Most utilittie apply shunt capacitors primarily as a tool in economic system design. Usually fixed (unswitched) 18-30 SECTION EIGHTEEN Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-31 shunt capacitors are applied to bring the light-load power factor to more or less 100%. Then, additioona automatically switched shunt capacitor banks are added to achieve an economic full-load power factor, which is usually in the order of 95% to 100%. These capacitors, in addition to their economic functions, such as reducing losses and releasing system capacity, improve system conditions substantially. Usually additional voltage control is needed, however, and this is most economically accomplished with voltage-regulating equipment. 18.9 OVERCURRENT PROTECTION General Principles. Coordination of overcurrent protection devices means their proper arrangemeen in series along a distribution circuit so that they function to clear faults from the lines and equipment in accordance with a prearranged sequence of operation. Fuse cutouts, automatic circuit reclosers, sectionalizers, and relayed circuit breakers are the overcurrent protective devices most commonly used. Ratings and characteristics can be obtained from appropriate product bulletins of the manufacturers. When the protective devices are properly applied and coordinated: They can eliminate service outages resulting from temporary faults. They reduce the extent of outages, that is, the number of users affected. They are helpful in locating the fault, thereby reducing the duration of interruptions. Main-Line Sectionalizing. Usually, the first protective device on a primary feeder is a circuit breaker or a power-class recloser located in the substation. If the circuit is overhead, the circuit breaker often is provided with reclosing relays so that it operates in much the same manner as a recloser. If the circuit is primarily underground, reclosing is not generally used. If portions of the main feeder and long branches extend beyond the zone of protection of the relayed breaker or recloser at the substation, additional overcurrent protective equipment usually will be installed out on the main feeder. Manually operated sectionalizing equipment such as pole-top disconnecting switches or solid blade cutouts also are installed at strategic locations along the main feeder to Provide a convenient means of isolating faults so that repairs can be made after other parts of the feeder are restored to service Provide means of connecting the feeder to adjacent feeders so that service can be maintained to most customers while repair or maintenance operations are taking place On underground feeders, this sectionalizing equipment is often in the form of 3-phase, manually operated, load-break switches. Branch-Circuit Protection. It is exceedingly important to isolate faults on branch and subbranch lines, even short ones, in order to maintain service on the rest of the feeder. Not only does the branchcirrcui protection protect the rest of the feeder, but it helps to pinpoint the location of the fault. Also, there is usually much more mileage and much more exposure in the branch circuit or laterral than in the feeder main. The simple expulsion-fuse cutout is almost universally used for branch and subbranch overcurrent protection. It may be used in combination with reclosers. On underground feeders, the lateral circuits usually are fused at the point where the main feeder is tapped to establish the lateral. Often, the fuses for several lateral circuits are grouped into a sectionaliizin equipment which may also incorporate main-feeder and load-break sectionalizing switches. Temporary Fault Protection. On overhead distribution circuits, a large portion of the faults are of a temporary nature or are potentially of a temporary nature. For example, some types of transitory Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-32 SECTION EIGHTEEN faults include momentary contacts with tree limbs and lightning flashover of insulators or crossarms where no sustained 60-Hz short-circuit current is established and no protective devices operate. Other types of faults which result in 60-Hz follow current can be of a transient nature if the circuit voltage can be removed quickly for a short period of time and then restored after the fault path has recovered adequate dielectric strength. Such faults can result from lightning flashovers, bird or animma contacts, conductors swinging together, etc. Reclosers and reclosing breakers provide the functiio of fault deenergization, pause for deionization of the arc path, and reestablishment of voltage. If the fault has disappeared during the “dead time,” the reclosure is successful. If not, one or more additional reclosing cycles may be attempted. If the fault persists after the prescribed number of reclosing operations, the breaker or recloser will lock open, or the fault will be removed by operatiio of a fuse or sectionalizer. It should be recognized that the reclosing function is provided to eliminate the effects of temporary faults only. If all faults were of a permanent nature, reclosing would be pointless. Also, temporary faults on branch circuits result in a momentary outage to all customers on the feeder when reclosing is used. Some utilities, in an effort to reduce the number of momentaries, are allowing the branch fuse to blow for temporary faults. (This is done by eliminating the instantaneous trip.) While this procedure reduces the number of momentaries seen by customers, it has the negative effect of creating a substantial interrupptio out of a temporary fault condition for the customers on the affected branch. To provide effective protection against temporary faults, all parts of the feeder should be within the zone of a reclosing device. That is, if the station recloser or relayed circuit-breaker sensing does not reach to the remote ends of the circuit, it should be supplemented with reclosers out on the line. (The term reach here is used with the meaning of “sense” faults or “sense and operate” for faults.) Permanent Fault Protection. Permanent faults are those which require repairs, maintenance, or replacement of equipment by the utility operating department before voltage can be restored at the point of fault. System overcurrent protection is provided to disconnect the faulted portion of the systte automatically so that an outage is experienced by a minimum number of consumers. Isolation of permanent faults is usually accomplished by the operation of fuse cutouts. It is also achieved in some cases by operation (to lock out) of reclosers, circuit breakers, or sectionalizers. Combination of Permanent and Temporary Fault Protection. If all faults were of a permanent nature, low-cost fuse cutouts would be the best solution for primary line protection. If all faults were temporary, automatic reclosing devices capable of covering the entire circuit would be the best solutiion In actual practice, both kinds of faults occur, and the problem becomes one of selecting the type of device or combination of devices to provide best overall results. For selection of a system of overcurrren protection, it is necessary to give proper consideration to many factors such as importance of service, total number of faults per year, ratio of temporary to permanent faults, cost to utility of serviic interruptions, and annual charge on investment. Selection of Overcurrent Protective Equipment—General. The one-line diagram of a distribution circuit, as shown in Fig. 18-18, will show how a well-coordinated installation of overcurrent protectiiv equipment can be made. At the left is the substation, which steps down the voltage from high-voltage subtransmission level to primary-distribution voltage level. It is at this point that the distribution system starts. A distribbutio substation usually has a number of radial 3-phase feeders radiating from it. However, for the purposes of illustration, only a single feeder will be considered, and it is shown extending to the right from the substation. At various points along the feeder, branch lines or laterals are tapped off and in some cases subbranches are tapped from these branches. There are, of course, loads (residennces stores, garages, etc.) all along the feeder, branches, and subbranches. Only a few of these loads are shown, for the sake of clarity of the diagram. It is general practice to install a fuse on the primary (incoming) line side of each distribution transforrmer as shown in Fig. 18-18. This may be a transformer internal fuse or an external fuse installed in a cutout. Transformer fusing will be discussed later. Figure 18-18 shows the basic system to which additional overcurrent protective equipment must be added to assure good service continuity. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-33 To properly apply overcurrent protective equipment to this system, it will be necessary to know the highest and lowest (maximum 3-phase and minimum line-to-ground or line-to-line) values of short-circuit currents which can flow if a fault should occur where the feeder leaves the substation, at each branch junction point, and at each subbranch junction point, as well as the minimum line-togrooun short-circuit current which could flow if a fault should occur at the end of any of the branches or subbranches. These short-circuit currents may be calculated easily by conventional methods. Clearing Nonpersistent or Temporary Faults. Operating records, as well as numerous studies, indicate that a reduction of 75% to 90% in the number of total outages on an overhead system can be attained by the installation of automatic reclosing devices (automatic circuit recloser or reclosing circuit breaker). The recloser or breaker will open the circuit “instantaneously” when a fault occurs, and reclose it after a short period of time. Referring to Fig. 18-18, automatic circuit reclosers will be applied to protect the entire system against temporary faults. To achieve this sort of protection, the first recloser should be installed on the main feeder at the substation or the power circuit breaker at the substation should be equipped with overcurrent and reclosing relays. In applying reclosers to do this job, certain factors must be considered: (1) The voltage rating of the recloser must be high enough to meet the requirements of the system. (2) Load current, or the amount of current which flows at the point of installation of the recloser under full-load conditions, should not exceed the amount of current which the manufacturer has rated the recloser to carry continuuousl (continuous-current rating). Recloser ratings are usually selected to be 140% of the peak load current of the circuit. This allows for normal load growth. (3) The highest value of short-circuit current which will flow through the recloser and which the recloser must interrupt. This value should not be greater than the highest value of current which the recloser is rated to interrupt (interrupting rating). Typically, a recloser will have a continuous rating of 560 A or less and an interrrupting ratiin of 16,000 A or less. A breaker, on the other hand, will usually handle at least 1200 A continuouusl and up to about 40 kA under short-circuit conditions. Referring to Fig. 18-19, a recloser or breaker with reclosing relays will be located at A to meet the three application principles mentioned above. This device will be depended on to clear nonpersiisten faults which occur in the feeder, branches, or subbranches, anywhere within its protecctiv orbit zone A (shown by dotted line in Fig. 18-19). This protective zone extends to the point where the minimum available short-circuit current, as determined by calculation, is equal to the smallest value of current which will cause the device to operate. This value of current required to operate the recloser or breaker is called minimum pickup current. For a recloser it is usually equal to twice the continuous current rating of the recloser. A fault beyond this zone may not cause the recloser or breaker A to operate, and therefore, another recloser, B, with a lower minimum pickup current rating, should be installed just inside of zone A, thus resulting in socallle overlapping protection. FIGURE 18-18 Distribution feeder. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-34 SECTION EIGHTEEN This second recloser, B in Fig. 18-19, is placed on the source side (side nearest source of power) of branch 5 so that it can protect the end of this branch from nonpersistent faults which may not cause recloser A to operate. It is applied according to the same considerations as was the recloser at A. It will be assumed that a fault on the feeder or any branch or subbranch beyond (to the right of) B will cause enough current to flow to operate the recloser at B. Every point on the entire circuit is now protected against nonpersistent faults because every point is within the protective zone of some reclosing device. Obviously, if every point were not within the protective orbit of some reclosing device, another recloser would have to be installed still farther out on the line. Clearing Persistent Faults. The first requirement of protecting the circuit against nonpersistent or transient faults has been taken care of by recloser application. It is necessary now to concentrate on the second and third requirements, that is, confining persistent faults to the shortest practical section of line and making persistent faults easy to locate. If a permanent fault occurs anywhere on the system beyond a recloser, the recloser will operate once, twice, or three times instantaneously, depending on adjustment, in an attempt to clear the fault. However, since a persistent fault will still be on the line at the end of these operations, it must be cleared by some means other than the instantaneous recloser operations. For this reason, the recloser is provided with one, two, or three time-delay operations, depending on adjustment. These additional operations are purposely slower (time-delay operations) to provide coordination with fuses or to allow the fault to “self-clear.” If the fault is still on the line after the last opening, the recloser will not close in but lock open. Referring to Fig. 18-20, curve A represents the instantaneous tripping characteristic with respect to time for the first and secoon opening of a conventional automatic circuit recloser. Curve B represents the tripping characteristics for the third and fourth openings. Following the fourth trip on time delay, the recloser will lock out and must be manually reclosed after the cause of the fault has been remedied. A persistent fault on a branch or subbranch line should not cause a recloser to lock open, since a fault on a relatively unimporrtan subbranch could shut down the entire circuit, in addition to being extremely difficult to locate. Therefore, some means should be employed to confine outages due to persistent faults to the branch or subbranch on which they occur. This may be done in either of two ways. FIGURE 18-20 Recloser tripping characteristics. FIGURE 18-19 Distribution feeder with automatic reclosers. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-35 One method by which persistent faults can effectively be dealt with is illustrated in Fig. 18-21. A fuse cutout is installed at each branch or subbranch junction to confine outages due to persistent faults to the branch or subbranch on which they occur, that is, fuses 1, 2, 3, 4, etc. The fuse cutout to be installed at a particular location must be of sufficiently high voltage rating to meet the voltage requirements of the circuit. Its continuous current rating must be equal to or greater than the full-load current at the point of installation. Its interrupting rating must be high enough so that it will successfully open the circuit for any persistent fault occurring beyond it. This may be checked by comparing the interrupting rating of the cutout with the maximum available short-circuit current calculated for the point on the system where the cutout is to be installed. For an ideal system, when the correct ratings of fuse links are used throughout the system, no fuse will be blown or even damaged by a temporary fault beyond it; that is, the recloser will open the circuui one, two, or three times on instantaneous operations without the fuse link being damaged. In many systems, however, where short-circuit levels are very high, it is sometimes impossible to preveen even the largest fuse from operating during a temporary fault. On a permanent fault, the first fuse link on the source side of the fault will be blown, and the circuit thus will be opened by the blowing of the fuse during the third or fourth (time-delay) operation of the recloser, before the recloser will lock open. Hence, the fault will be isolated by the fuse, and the recloser will reset automaticcally restoring service everywhere except beyond the blown fuse. The recloser should never lock open on a permanent fault beyond the fuse if it has been properly coordinated with the recloser. Extensive coordination tables are available, as illustrated in Table 18-4, to simplify and facilitate the job of coordinating reclosers with fuse links. Recloser-Fuse Coordination. Figure 18-22 shows the time-current characteristic curves of the automatic circuit recloser similar to those shown in Fig. 18-20. On these curves, the time-current (TC) characteristics of a fuse C are superimposed. It will be noted that fuse curve C is made up of two parts; that is, the upper portion of the curve (low current range) represents the total clearing-time TC curve, and the lower portion (high current range) represents the melting TC curve for the fuse. The intersection points of the fuse curves C with the recloser curves A and B illustrate the limits between which coordination will be expected. Basically, this is correct within the interest of simpliccity However, to establish intersection points a and b accurately and to prepare coordination charts, it is necessary that the characteristic curves of both recloser and fuse be shifted, or modified, to take into account alternate heating and cooling of the fusible element as the recloser goes through its sequence of operations. For example, if the fuse is to be protected for two instantaneous openinngs it is necessary to compute the heat input to the fuse during these two instantaneous recloser operations. Curve Ain Fig. 18-23 is the equivalent TC characteristic of two instantaneous openings (A) and is compared with the fuse-damage curve, which is 75% of the melting-time curve of the fuse. This will establish the high current limit of satisfactory coordination indicated by intersection point b. To establish the low current limit of successful coordination, compare the total heat input to the fuse FIGURE 18-21 Distribution feeder with automatic reclosers and fuse cutouts. Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-36 SECTION EIGHTEEN represented by curve B, which is equal to the sum of two instantaneous (A) plus two time-delay (B) operations, with the total clearing-time curve of the fuse. The point of intersection is indicated by a. On the basis of all corrections added, the fuse will coordinate successfully with recloser between the current limits of aand b. To further clarify what is meant by coordination within prescribed limits, refer to Fig. 18-21— branch 5 and recloser B—and also Fig. 18-23 to establish how coordination is achieved between the limits of aand b. Assume that fuse 5 beyond recloser B is to be protected against blowing or being damaged during two instantaneous operations of the recloser in the event of a transient fault at X. If the maximum calculated short-circuit current at the fuse location does not exceed the magnitude of current indicated by b, the fuse will be protected against blowing during all transient faults. By observation of the characteristics in Fig. 18-23, for any magnitude of short-circuit current less than bbut greater than a, the recloser will trip on its instantaneous characteristic once or twice to clear the fault before the fuse-melting characteristic is approached. On the other hand, if the fault at X is persistent, the fuse at 5 should blow before the recloser B locks out. If the minimum (line-to-ground) calculated short-circuit current available at the end of branch 5 is substantially greater than the FIGURE 18-22 Recloser and fuse time-current characteristics. TABLE 18-4 Automatic Recloser and Fuse Range of Coordination* Fuse link ratings, rms A 25T 30T 40T 50T 65T 80T 100T 140T Range of coordination, rms A 50 Min 190 480 830 1200 1730 2380 Max 620 860 1145 1510 2000 2525 70 Min 140 180 365 910 1400 2000 2750 Max 550 775 1055 1400 1850 2400 3200 100 Min 200 200 200 415 940 1550 2280 Max 445 675 950 1300 1700 2225 3050 140 Min 280 280 280 720 710 1750 Max 485 810 1150 1565 2075 2875 200 Min 400 400 400 880 3200 Max 960 1380 1850 2600 4000 280 Min 620 620 1350 Max 1500 2200 4000 *Recloser sequence: two instantaneous plus two standard time-delay operations. Recloser rating, rms A (continuous) Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTIONPOWER DISTRIBUTION 18-37 current indicated by a, the fuse will blow (Fig. 18-23) in accordance with the total clearing characteristic, probably before the first time-delay characteristic of the recloser is approached. The correct fuse link for any application may be selected by comparing its TC characteriistic curve with those of the recloser and making certain allowances and corrections as shown. However, tables have been prepared similar to Table 18-4 to simplify greatly the job of coordinating reclosers with fuse links. This table shows the maximum and minimmu currents at which certain ratings of fuse links will coordinate with certain ratings of reclosers. The only requirement in their use is a knowledge of the available short-circuit currents and load currents on the system. Other sequences of recloser operation can be employed, but one instantaneous and two timedeela operations is the combination most widely used. In some cases, it is necessary to coordinate recloser operation with a relayed breaker at the substation. The principles of coordination are similla to the previous discussions, but a detailed study is beyond the scope of this handbook. This is also true of the application requirements for power-class reclosers for substation and line protection. Fuse-to-Fuse Coordination. It may be desirable to use more than two fuses in series beyond a recloser in order to reduce the number of consumers affected by an outage. An example of this would be the fuses at points 7, 8 and at transformers on branch 8 in Fig. 18-21. The coordinatiio of these fuses in series beyond the recloser B may be accomplished by coordinating adjaceen fuses first with each other and then with the recloser in the manner just outlined. Figure 18-24 illustrates the general principle of coordinattin fuses in series. Fuse 7 is called the protected fuse, and fuse 8 is called the protecting fuse. For perfect coordinattion fuse 8 must clear the circuit during a fault anywhher beyond it, such as at X, before fuse 7 is damaged or partially melted. From this can be seen the requirement for melting-time–current curves plotted to minimum values and total-clearing-time–current curves plotted to maximmu values for each fuse-link rating. Total-clearing-time curves represent the total time, including melting time and arcing time, plus manufacturing tolerance, that it takes the fusible elements to clear the circuit. Melting-time curves represent the minimum time, based on factory test, at which the fusible element melts for various currents. From the melting-time curves, damaging-time curves can be determined by applying a factor of safety. It usually is suggesste that the damaging-time curve be made by taking 75% of the melting time (in seconds) of a particular size at various current values. To establish coordination of two fuses in series, it is necessary to compare the total-clearingtiimecurrent curve of the protecting fuse with the damage-time–current curve of the protected fuse. If there is no intersection of these two curves throughout their entire current range, coordination or selectivity can be expected. Where there is an intersection of the curves, the current value indicated by the point of intersection will establish the limit of selectivity. FIGURE 18-23 Recloser and fuse time-current characterisstics FIGURE 18-24 Fuse time-current characterisstics Downloaded from Digital Engineering Library @McGraw-Hill (www.digitalengineeringlibrary.com) Copyright © 2006 The McGraw-Hill Companies. All rights reserved. Any use is subject to the Terms of Use as given at the website. POWER DISTRIBUTION18-38 SECTION EIGHTEEN Because of the inherent characteristics of fuses, the maximum available short-circuit current in that section (determined by calculation) controlled by the protecting link (8 in Fig. 18-24) is the determining current which establishes coordination possibilities. Most fuse-link manufacturers publish tables which make coordination very simple. These tables eliminate the necessity of comparing actual fuse-characteristic curves. Table 18-5 is illustrative of tables used for fuse-to-fuse coordination. The values in the left-hand column are the protecting fuse ratings and the values across the top are the protected fuse ratings. The numerical values in the table show the magnitude of current or curve intersection points at which, or below which, fuse 7 will be protected by fuse 8. These current magnitudes are maximum values; in other words, for any shortcirrcui current greater than that shown, fuse 7 will be damaged. Hence, a larger-rated fuse will have to be selected for location 7 or else its position must be changed. Isolation by Sectionalizer. Another method of isolating persistent faults is to install a device, known as a sectionalizer, at locations where a fuse might otherwise be used. A sectionalizer is a device which counts the operations of a backup automatic-interrupting device such as a recloser. It has no interrupting capacity of its own but operates in a predetermined coordination scheme to open a faulted lateral before the backup device locks out. The sectionalizer opens the circuit after a predetermined number (usually two or three) of operations of a reclosing device. Its opening operation occurs during a period when the reclosing device is open. It can be used to replace a lateral sectionalizing fuse or to replace a lateral recloser where interrupting requirements have grown beyond the capability of the recloser. Among its operating advantages are It allows coordination with breakers or reclosers where fault current is above 5000 A. Such coordinaatio usually is impossible with expulsion fuses. It can provide a new sectionalizing point on an existing circuit without upsetting existing overcurrren coordination, since the device operates as a counter and does not introduce another level of time-current coordination. Equipment Protection General. It is necessary to provide overcurrent protection for distribution equipment such as capacitors and distributio